This invention relates to the treatment of gas streams, and in particular to an improved method for solvent extraction of hydrogen sulfide and other contaminants from sour gas feed stocks, tail gases, ammonia, and flue gas streams.
Hydrocarbon fuel sources such as crude oil, natural gas and coal are often contaminated by significant amounts of sulfur compounds. When the sulfur compounds are burned, objectionable odors and pollutants are created. The extraction of sulfur, generally present in the form of hydrogen sulfide, from feedstocks and tail gases is thus a vital aspect of refinery, natural gas and coal liquification operations.
Hydrogen sulfide is usually removed by solvent extraction, with subsequent regeneration and recycle of the solvent. In many cases, carbon dioxide is also present in significant amounts. The solvent must therefore be selective for hydrogen sulfide in the presence of carbon dioxide. Suitable solvents include aqueous solutions of secondary and tertiary amine, such as diisopropylamine (DIPA), methyldiethanolamine (MDEA) and triethanolamine (TEA). The feedstock gas is contacted with the amine at relatively low temperatures in an absorber to remove the hydrogen sulfide. This step produces a rich amine stream, loaded with H2S and CO2. This rich amine is passed to a stripper/regenerator, usually a tray type column. The solvent is heated and gives off a concentrated acid gas, leaving a lean amine stream that is recycled as fresh solvent to the absorber. The H2S rich concentrated acid gas is routed to a sulfur recovery unit to be converted into elemental sulfur by the well known Claus process:
H2S+⅔O2xe2x86x92SO2+H2Oxe2x80x83xe2x80x831)
2H2S+SO2⇄2H2O+3Sxe2x80x83xe2x80x832)
The Shell Claus Off-gas Treating (SCOT) process for removing sulfur components from Claus plant tail gas was first brought on stream in 1973.Since then, the process has been widely used in the oil refining and natural gas industries, with more than 150 units constructed all over the world. In the standard SCOT process, sulfur compounds in Claus plant tail gas are catalytically converted into hydrogen sulfide. After cooling, the hydrogen sulfide is removed by solvent extraction, in the manner already discussed. The SCOT off-gas (the gas not absorbed in the absorber) is incinerated.
The advantage of the SCOT process is the use of familiar refining technologies. Application of the SCOT process for different types of gas treating units and Claus units raises special design considerations. The sulfur dioxide emissions from the Claus and tail gas treating plants make a significant contribution to the total sulfur dioxide emissions from a refinery. It is therefore important to reduce the sulfur dioxide emissions from these plants to the lowest possible levels.
The standard SCOT process is able to recover 99.9% of total sulfur, resulting in a 250 ppmv sulfur concentration in the SCOT off-gas. In recent years, the demand for higher sulfur recovery efficiencies has resulted in the development of two improved versions to the SCOT process. These are the Low-sulfur SCOT and the Super-Scot processes. The new processes lower the total sulfur content in the SCOT off-gas to less than 50 ppmv, while maintaining low operating costs.
The Low sulfur-SCOT (LS-SCOT) version is characterized by the use of an inexpensive additive to the amine solvent. This additive improves the regeneration of the solvent, and produces regenerated solvent having less hydrogen sulfide, which in turn results in a lower off-gas hydrogen sulfide concentration. Treated off-gas specifications as low as 10 ppmv hydrogen sulfide can be achieved. Because of the additive, LS-SCOT units are preferably designed as a stand-alone SCOT unit. However, the LS-SCOT version has also been tested successfully on integrated SCOT units with DIPA and MDEA solvents.
The Super-SCOT version is based on improved stripping by two-stage regeneration and improved absorption by using a lower lean solvent temperature. These two features can be applied separately or in combination.
The performance of an amine regenerator is normally limited by the equilibrium conditions in the bottom. This condition leads to a direct relationship between stripping steam and the solvent leanness. In order to produce leaner solvent (mol H2S/mol amine), a higher specific steam rate (kg steam/m3 solvent) is required. As in the LS-SCOT method, a leaner regenerated solvent will result in a lower hydrogen sulfide concentration in the SCOT off-gas. However, it is not necessary to regenerate the entire solvent flow to this lower leanness level. The Super-SCOT process therefore uses two-stage regeneration, in which part of the amine solvent flow is more deeply stripped. The resulting super-lean solvent is routed to the top tray of the absorber, while the normal lean solvent enters half-way up the absorber. The use of an additive changes the equilibrium conditions; less steam is required for the same leanness, or a greater leanness can be achieved with the same steam rate.
It is well known that the solubility of hydrogen sulfide in amine solvents increases when the temperature is lowered. Thus, using a lower amine temperature results in improved extraction of hydrogen sulfide from the feed gas, which enables a lower hydrogen sulfide concentration to be achieved compared to the normal SCOT process.
The Super-SCOT method has been shown to achieve a hydrogen sulfide concentration of 10 ppmv H2S or a total sulfur concentration of less than 50 ppmv, and to reduce steam consumption by 30% compared to the standard SCOT unit. Cascading the solvent similar to the standard SCOT is an option to save operating costs.
Because the acid gas from the SCOT regenerator is recycled back to the Claus feed gas, it is important that inert ingredients in the concentrated acid gas be as low as possible in order to avoid build up of inerts, which can severely limit throughput in the Claus/SCOT system. As already discussed, carbon dioxide, which is not treated by the SCOT process, is often present in significant quantities. Therefore, the solvent used in the SCOT process should preferably absorb hydrogen sulfide more readily than it will absorb carbon dioxide.
Because the capacity of the sulfur recovery plant is critical to the capacity for producing finished product, there is continued interest in improving Claus plant capacities and several incremental improvements have been developed for the refining industries.
U.S. Pat. No. 4,263,270, issued to Groenendaal et al., discloses a process for handling gases containing large quantities of hydrogen sulfide and carbon dioxide. Hydrogen sulfide and CO2 are extracted by absorption, then the absorbed gas is subjected to the Claus process. The Claus off-gas is reacted in the presence of a catalyst with hydrogen or carbon monoxide, followed by a second extraction that is CO2 selective. Some of the feed gas is bypassed around the Claus unit in some cases.
U.S. Pat. No. 4,153,674, issued to Verloop et al., discloses a process for treating a gas stream that is high in CO2, low in H2S, and also contains significant amounts of COS or other organic sulfur compounds. The process is quite similar to that disclosed in Groenendaal et al., except that the feed gas always bypasses the Claus unit, and is combined with the Claus off-gas before entering the catalytic reactor.
U.S. Pat. No. 4,001,386, issued to Klein et al., discloses a process using cascaded absorbers with a common desorbtion column. A Claus plant and reactor like that in Groenendaal treat the first absorber off-gas before it is fed to the second absorber. The absorbent from the second absorber is cascaded through the first absorber before being desorbed, so that the desorber always processes absorbent having higher H2S partial pressure than that of the Claus off-gas.
U.S. Pat. No. 4,153,674, issued to Verloop et al., discloses a Claus process adapted for increasing the H2S concentration in a gas stream, particularly a gas stream to be fed to a Claus unit. In this process, the feed gas stream flow rate is measured prior to entering an absorber. If this measurement falls below a preset value, a second absorber is connected in tandem into the process similar to the cascaded configuration of Klein et al.
U.S. Pat. No. 4,483,834, issued to Wood, discloses a solvent extraction system that uses an added splitter column to separate the regenerator overhead stream into an H2S stream and a CO2 stream, followed by recycling the CO2 stream back to the absorber inlet. The method has the disadvantage that separation of H2S and CO2 is reduced by recycling the CO2.
The foregoing patents show the continued interest and need for the development of processes that can remove contaminants from gas feedstocks with lower operating costs and more complete removal of sulfur from the gas. A process that can achieve these results with lower capital investment is also desired.
The object of the present invention is to remove a selected contaminant, by means of solvent extraction, from a gas stream that also contains unselected components that can be absorbed in significant amounts. Another object is to achieve the previous object with minimal modification of existing apparatus. Still another object, for streams containing sulfurous contaminants, is to achieve more complete overall removal of sulfur from the gas stream than the conventional SCOT process. A final object is to maximize the capacity of downstream units by reducing the amount of unselected components present in the gas stream discharged from the regenerator.
In general, these objects are achieved by a modified solvent extraction method. The solvent used should have a marked capacity for absorption of the selected contaminant, and relatively less absorption capacity for the unselected components in the gas stream. That is, the solvent used has relative absorption constants greater than one, for the selected contaminants relative to the unselected components. These constants vary directly in proportion to the partial pressure of the selected contaminants in the feed stream, i.e. the absorption capacity of the solvent for the selected contaminants increases with the partial pressure of the contaminants, and does so more quickly than the absorption capacity for the unselected components. Either physical solvents, such as water, propylene carbonate or methyl cyanoacetate, or chemical solvents, such as monoethanol amine (MEA), diethanol amine (DEA) or N-methyl-diethanol amine (MDEA) can be used in such a process. A portion of the contaminant rich gas from the regenerator overhead is recycled and mixed with the gas stream entering the absorber. This raises the partial pressure of the selected contaminants in the gas fed to the absorber, causing a shift in the relative absorption constants that in turn causes greater absorption of the selected contaminants and less absorption of the unselected components. Thus, the separation between the selected contaminants and the unselected components is improved.
An obvious advantage of the improved separation for sulfurous contaminants is that less of the unselected components are sent to any downstream sulfur recovery unit (e.g. CO2 to a Claus process), so the sulfur recovery unit need not be sized to handle the additional gas loading. Greater rejection of the unselected components at the absorber results in a lower total mass flow rate to the sulfur removal unit without significantly affecting the flow rate of the selected contaminants. Thus, either a smaller, less expensive sulfur removal unit may be used or an existing sulfur removal unit can be run at greater capacity.
Another advantage of the invention is the more complete removal of the selected contaminants, due mainly to the improved absorption achieved from increasing the partial pressure of the contaminants fed to the absorber. The efficiency of the basic absorption-regeneration process and the overall efficiency of tail gas treatment are improved.
Finally, the method of the invention can be practiced using a single absorber, instead of both a non-selective absorber and a selective absorber, as in the Groenendaal et al., Klein et al., and Verloop et al. methods. The method also does not require additional columns for further processing of the regenerator overhead gas, as in the Wood method. This results in capital and construction cost savings. However, cascaded absorbers and regenerators can still be employed to improve yield or operating costs, just as in the aforementioned methods.
These and other advantages and features of the invention will be apparent from the following detailed description and the associated drawings.